The invention generally relates to a process for treating a heavy hydrocarbon crude oil, also referred to herein as “crude oil.” More particularly, the process described herein is directed to upgrading a heavy hydrocarbon crude oil feedstock by a hydroprocessing catalyst assisted hydrotreatment. Although the term hydrocracking is often applied to these types of processes, the term hydroconversion (or hydroprocessing or hydrotreatment) will be used herein to avoid confusion with conventional gas oil hydrocracking.
Heavy crude oils are composed chemically of a very broad range of molecules differing widely in molecular weight (MW) and chemical properties. In addition, heavy crude oils from different formations and locations around the world have different characteristics. Because of the large number of variable characteristics of heavy crude oil around the world, it is difficult to define heavy crude oils simply in terms of individual molecular components. Instead, various separation procedures are used to break down the feed into a number of smaller fractions that are more consistently identifiable. One such technique involves separation into solubility classes using solvents of varying polarity and further separation using column chromatography. These fractions can then be further characterized in terms of an average structure by nuclear magnetic resonance (NMR) or other analytical technique known to persons skilled in the art.
Despite the fact that heavy crude oils range widely in their composition and physical and chemical properties, they are typically characterized by having a relatively high viscosity, high boiling point, high Conradson carbon residue, low API gravity (generally lower than 25), and high concentration of sulfur, nitrogen, and metallic impurities. Additionally, the hydrogen to carbon ratio of heavy crude oils is lower than desirable. Further, much of the crude oil around the world also contains relatively high concentration of sulfur. As used herein, the term crude oil, or heavy crude oil, is understood to include heavy hydrocarbon crude oil, tar sands, bitumen, and residual oils, i.e., bottom of the barrel or vacuum bottom oils.
During the last few decades, environmental and economical considerations have required the development of processes to remove heteroatom such as, for example, sulfur, nitrogen, oxygen, and metallic impurities, from the heavy hydrocarbon crude oil feedstocks, as well as to convert the heavy hydrocarbon crude oil feedstocks to lower their boiling points. Such processes generally subject the heavy hydrocarbon crude oils or their fractions to thermal cracking or hydrocracking to convert the fractions having higher boiling points to fractions having lower boiling points, optionally followed by hydrotreating to remove the heteroatoms.
Petroleum hydrocarbons are subjected to a variety of physical and chemical processes to produce higher value products. For example, in a gas-oil separator (GOSP), crude is processed to remove water and other contaminants, such as salt, to achieve BS&W requirements. BS&W requirements are a measure of bottom sediment and water, usually expressed as a percentage by weight.
Refining and other high temperature treatments are well known in the art. Technologies for upgrading heavy crude oil, including bitumen and residual oils, to give lighter and more useful oils and hydrocarbons can be broadly divided into two types of processes: carbon rejection processes and hydrogen addition processes. Both of these processes employ high temperatures (usually greater than 400° C.) to “crack” the long chains or branches of the hydrocarbons that make up the heavy hydrocarbon crude oil. In the carbon rejection process, the heavy hydrocarbon crude oil is converted to lighter oils and coke. In some carbon rejection processes, the coke is used elsewhere in the refinery to provide heat or fuel for other processes.
Hydrogen addition processes involve reacting heavy crude oils with an external source of hydrogen resulting in an overall increase in hydrogen to carbon ratio. One benefit of hydrogen addition processes compared to carbon rejection processes, is that in the hydrogen addition process, formation of coke is prevented through the addition of high pressure hydrogen. Examples of hydrogen addition processes include: catalytic hydroconversion (hydrocracking) using active HDS catalysts; fixed bed catalytic hydroconversion; ebullated catalytic bed hydroconversion; thermal slurry hydroconversion (hydrocracking); hydrovisbreaking; and hydropyrolysis.
While such treatments reach the desired goal of lowering the density of hydrocarbons or separation of desired hydrocarbon fractions, these treatments include several drawbacks including possible undesirable cracking. It is desirous to avoid the negative effects associated with such treatments, while still processing the original hydrocarbon to reduce sulfur content and/or molecular weight of the original crude.
Water Treatment
Traditional refining processes are also sensitive to water contained in crude. Feedstock from the oil field typically contains water. Processed oil that is to be transported by pipeline must generally be free of water to meet pipeline specification. Similarly, processed oil must generally be free of water to be sold. A large portion of the water contained in crude is free water that is not dissolved in hydrocarbon. Often though, the water is highly dispersed in droplets throughout the oil, thus forming an emulsion. Emulsions have varying characteristics with some emulsions being tightly bound such that it is difficult to separate the water phase from the oil phase. The separation of water from oil can be quite costly. Therefore, there is a need for a cost effective method to remove water from petroleum feed. It would be desirable for this cost effective method to efficiently remove trace amounts of water as well as or after achieving gross separation.
Several methods of reducing the viscosity of the petroleum products in order to facilitate extraction of water from the emulsion are known in the art, including heating the petroleum. It has been proposed that a geologic formation can be heated via electrodes deployed in the ground using resistance heating to break the water in situ.
Chemical methods are commonly used to separate water-in oil emulsions and oil-in water emulsions. Conventional demulsification techniques can be very energy and chemical intensive making the process expensive. Furthermore, the demulsification agents may have undesirable effects on the petroleum product, since they are typically hydrophilic surfactants or synthetic/natural flocculants. It is desirable to provide a chemical-free method of breaking emulsions such that the product quality is not deteriorated through the addition of extraneous chemical additives.
Sulfur Removal
Since much of the world's crude oil contains sulfur in quantities that are too high for a finished product, many operations use desulfurization techniques in their processes. Sulfur occurs in many forms in crudes or in light oil, middle oil or other fractions or products. These forms of sulfur can include hydrogen sulfide, organic sulfides, organic disulfides, mercaptans (or thiols), and aromatic ring compounds, such as thiophene, benzothiophene (BT), dibenzothiophene (DBT) (jointly “thiophenic sulfur”) and their alkylated homologues. Depending on the boiling point fraction of the oil, the form of the ring sulfur differs. Desulfurization of the 4,6-dialkyl dibenzothiophene present in substituted dibenzothiophenes can be extremely difficult. Of the thiophenic sulfur compounds, the alkyl substituted dibenzothiophenes are particularly resistant to hydrodesulfurization. Conventional hydrodesulfurization methods to remove sulfur from the residual of a distillation column are often carried out at a temperature over 400 deg C. with hydrogen gas applied to the charge. Catalyst such as cobalt and molybdenum on alumina are used to enhance the reaction, as disclosed in US Publication No. 2006-0254956 A1, which is herein incorporated in its entirety.
Crude oil varies so greatly by nature, with large differences not only in the hydrocarbon mixture but also in other organic compounds containing heteroatoms such as sulfur, oxygen, nitrogen and metals, such as nickel and vanadium, as well. Most crude oil undergoes distillation processes to refine the crude to desired products. It would be desirable to take advantage of resources available at the production field or at shipside to achieve some degree of desulfurization before transporting the crude for distillation processing.
Sulfur compounds are also a consideration in hydroprocessing and hydrotreating. Hydroprocessing refers to the processes in which hydrogen gas is used as part of a conversion of various feedstocks (including aromatics and heavy naphthas) into useful products. Hydroprocessing achieves this outcome through the hydrogenation and the breakup of polynuclear aromatics. Significant portions of these feedstocks are converted through hydrocracking into smaller-sized and more useful product constituents. In conventional hydrotreating processes, the hydrogenation reactions of aromatic compounds play an important role, mostly because heavy residual compounds are normally aromatic in nature. Therefore, the complete or partial saturation of these compounds by hydrogen addition is an important step in their cracking into smaller, more valuable compounds. Conventional heavy oil hydrocracking processes require relatively high temperatures and high pressures, which are often over 410 deg C. and greater than 1000 psi, respectively. Consequently, processing of the crude under more mild conditions would be desirable.
When a petroleum fraction that contains sulfur is being catalytically cracked, the products of the catalytic cracking usually contain sulfur impurities, which normally require removal through hydrotreating in order to comply with relevant product specifications. Such hydrotreating is done either before or after catalytic cracking. Conventionally, feeds with substantial amounts of sulfur, i.e. more than 500 ppm sulfur, are hydrotreated with conventional hydrotreating catalysts under conventional conditions, thereby changing the form of most of the sulfur in the feed to hydrogen sulfide. The hydrogen sulfide is then removed by amine absorption or related stripping techniques. These techniques, while removing significant amounts of hydrogen sulfide, often leave traces of the most troublesome sulfur compounds, such as thiophenic sulfur, in the hydrocarbon stream. These compounds are less responsive to conversion techniques.
Hydrodesulfurization, also called hydrotreating, can be effective in reducing the level of sulfur to moderate levels, e.g. 500 ppm, without a severe degradation of olefins or other desirable products. The refractory sulfur compound's DBT (dibenzothiophene) can be removed by distillation; however, it requires additional capital expenditure and results in a degraded product, i.e. downgrading a portion of automotive diesel oil to heavy fuel oil. Hydrotreating of any of the sulfur-containing fractions of cracked gasoline causes a reduction in the olefin content. Current sulfur specifications can often be met without excessive octane loss by hydrotreating only the heaviest, most sulfur-rich and olefin-poor portion of the FCC (Fluid Catalytically Cracked) gasoline. A new method would be advantageous that would preserve yield and octane while removing sulfur from the relatively olefinic light and mid-range portions of the FCC gasoline pool.
Furthermore, in order remove sulfur and heavy metals satisfactorily, the catalytic material must be in intimate contact with the crude oil; however, the prior arts have failed to achieve such contact.
Thus, there remains a long felt need for a method of removing sulfur from crude oil feeds that contain sulfur compounds, including thiophenic sulfur compounds, under moderate process conditions while maintaining the characteristics of the feed stream.
Furthermore, crude oil produced from a well is often in the form of an emulsion consisting of oil and water. Therefore, it would be desirable to separate this emulsion into an oil phase and aqueous phase and then remove the sulfur contained within the oil phase, under moderate process conditions while maintaining the characteristics of the feed stream.